This invention relates to a process for recovering ethane and heavier hydrocarbons from pressurized liquefied gas mixture comprising methane and heavier hydrocarbons.
Because of its clean burning qualities and convenience, natural gas has become widely used in recent years. Many sources of natural gas are located in remote areas, great distances from any commercial markets for the gas. Sometimes a pipeline is available for transporting produced natural gas to a commercial market. When pipeline transportation is not feasible, produced natural gas is often processed into liquefied natural gas (which is called xe2x80x9cLNGxe2x80x9d) for transport to market.
The source gas for making LNG is typically obtained from a crude oil well (associated gas) or from a gas well (non-associated gas). Associated gas occurs either as free gas or as gas in solution in crude oil. Although the composition of natural gas varies widely from field to field, the typical gas contains methane (C1) as a major component. The natural gas stream may also typically contain ethane (C2), higher hydrocarbons (C3+), and minor amounts of contaminants such as carbon dioxide (CO2), hydrogen sulfide, nitrogen, dirt, iron sulfide, wax, and crude oil. The solubilities of the contaminants vary with temperature, pressure, and composition. At cryogenic temperatures, CO2, water, other contaminants, and certain heavy molecular weight hydrocarbons can form solids, which can potentially plug flow passages in cryogenic equipment. These potential difficulties can be avoided by removing such contaminants and heavy hydrocarbons.
Commonly used processes for transporting remote gas separate the feed natural gas into its components and then liquefy only certain of these components by cooling them under pressure to produce liquefied natural gas (xe2x80x9cLNGxe2x80x9d) and natural gas liquid (xe2x80x9cNGLxe2x80x9d). Both processes liquefy only a portion of a natural gas feed stream and many valuable remaining components of the gas have to be handled separately at significant expense or have to be otherwise disposed of at the remote area.
In a typical LNG process, substantially all of the hydrocarbon components in the natural gas that are heavier than propane (some butane may remain), all xe2x80x9ccondensatesxe2x80x9d (for example, pentanes and heavier molecular weight hydrocarbons) in the gas, and essentially all of the solid-forming components (such as CO2 and H2S) in the gas are removed before the remaining components (e.g. methane, ethane, and propane) are cooled to cryogenic temperature of about xe2x88x92160xc2x0 C. The equipment and compressor horsepower required to achieve these temperatures are considerable, thereby making any LNG system expensive to build and operate at the producing or remote site.
In a NGL process, propane and heavier hydrocarbons are extracted from the natural gas feed stream and are cooled to a low temperature (above about xe2x88x9270xc2x0 C.) while maintaining the cooled components at a pressure above about 100 kPa in storage. One example of a NGL process is disclosed in U.S. Pat. No. 5,325,673 in which a natural gas stream is pre-treated in a scrub column in order to remove freezable (crystallizable) C5+ components. Since NGL is maintained above xe2x88x9240xc2x0 C. while conventional LNG is stored at temperatures of about xe2x88x92160xc2x0 C., the storage facilities used for transporting NGL are substantially different, thereby requiring separate storage facilities for LNG and NGL which can add to overall transportation cost.
It has also been proposed to transport natural gas at temperatures above xe2x88x92112xc2x0 C. (xe2x88x92170xc2x0 F.) and at pressures sufficient for the liquid to be at or below its bubble point temperature. This pressurized liquid natural gas is referred to as xe2x80x9cPLNGxe2x80x9d to distinguish it from LNG, which is transported at near atmospheric pressure and at a temperature of about xe2x88x92162xc2x0 C. (xe2x88x92260xc2x0 F.). Exemplary processes for making PLNG are disclosed in U.S. Pat. No. 5,950,453 (R. R. Bowen et al.); U.S. Pat. No. 5,956,971 (E. T. Cole et al.); U.S. Pat. No. 6,016,665 (E. T. Cole et al.); and U.S. Pat. No. 6,023,942 (E. R. Thomas et al.). Because PLNG typically contains a mixture of low molecular weight hydrocarbons and other substances, the exact bubble point temperature of PLNG is a function of its composition. For most natural gas compositions, the bubble point pressure of the natural gas at temperatures above xe2x88x92112xc2x0 C. will be above about 1,380 kPa (200 psia). One of the advantages of producing and shipping PLNG at a warmer temperature is that PLNG can contain considerably more C2+ components than can be tolerated in most LNG applications.
Depending upon market prices for ethane, propane, butanes, and the heavier hydrocarbons, it may be economically desirable to transport the heavier products with the PLNG and to sell them as separate products. This separation of the PLNG into component products is preferably performed once the PLNG has been transported to a desired import location. A need exists for an efficient process for separating the C2+ components from the PLNG.
The invention is an absorption process for recovering C2+ components from a pressurized liquid mixture comprising C1 and C2+. The pressurized liquid mixture is at least partially vaporized by heating the liquid mixture in a heat transfer means. The heat transfer means provides refrigeration to an absorption medium that is used in treating the vaporized mixture in an absorption zone. The vaporized mixture is passed to an absorption zone that produces a first stream enriched in C1 and a second stream enriched in C2+ components. The pressurized liquid mixture is preferably pressurized liquid natural gas (PLNG) having an initial pressure above about 1,724 kPa (250 psia) and an initial temperature above xe2x88x92112xc2x0 C. (xe2x88x92170xc2x0 F.). Before being vaporized, the pressurized liquid mixture is preferably boosted in pressure to approximately the desired operating pressure of the absorption zone.